The present disclosure relates generally to drilling systems and more particularly to tools for sampling and analyzing formation fluid.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
Wells are generally drilled into a surface (land-based) location or ocean bed to recover natural deposits of oil and gas, as well as other natural resources that are trapped in geological formations in the Earth's crust. A well is often drilled using a drill bit attached to the lower end of a drill string, which includes drillpipe, a bottom hole assembly, and other components that facilitate turning the drill bit to create a borehole. Drilling fluid, or “mud,” is pumped down through the drill string to the drill bit during a drilling operation. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in an annulus between the drill string and the borehole wall.
Information about the subsurface formations, such as measurements of the formation pressure, formation permeability, and recovery of formation fluid samples, may be useful for predicting the economic value, the production capacity, and production lifetime of a subsurface formation. Downhole tools, such as formation testers, may perform evaluations in real-time during sampling of the formation fluid.
When evaluating subsurface formations containing crude oil, a measurement of oil formation volume factor may be useful for appraising the formation. Formation volume factor is defined as a volume ratio of the crude oil at reservoir conditions to the oil at its stock tank condition. Stock tank oil condition represents a standard temperature and pressure condition (e.g., 25° C. and 1 atm). Formation volume factor may be used to estimate an amount of liquid oil within the reservoir. Typically, samples of formation fluid are brought to the surface for laboratory evaluation, and PVT analysis of the sample yields a measure of formation volume factor.